Retrieving a subsea tree plug

ABSTRACT

A method for riserless intervention of a subsea well includes: lowering a pressure control assembly (PCA) from a vessel to a subsea production tree; fastening the PCA to the tree; deploying a plug running tool (PRT) into the PCA, wherein the PRT comprises a latch, an anchor, and a stroker; engaging the latch with a plug of the tree; engaging the anchor with the PCA; and operating the stroker to pull the latch and the plug from the tree.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims benefit of U.S. Prov. Pat. App. No. 61/374,182 (Atty. Dock. No. WWCI/0014USL), filed Aug. 17, 2010 and U.S. Prov. Pat. App. No. 61/408,036 (Atty. Dock. No. WWCI/0014USL2), filed Oct. 29, 2010, both of which are herein incorporated by reference in their entireties.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to retrieving a subsea tree plug.

2. Description of the Related Art

Subsea crude oil and/or natural gas wells frequently require workover to maintain adequate production. Workover operations may include perforating, gravel packing, production stimulation and repair of a downhole completion or production tubing. During the workover, specialized tools are lowered into the well by means of a wireline and winch. This wireline winch is typically positioned on the surface and the workover tool is lowered into the well through a lubricator and blowout preventer (BOP). Workover operations on subsea wells require specialized intervention equipment to pass through the water column and to gain access to the well. The system of valves on the wellhead is commonly referred to as a production or Christmas tree and the intervention equipment is attached to the tree with a blowout preventer (BOP).

The commonly used method for accessing a subsea well first requires installation of a BOP with a pre-attached tree running tool (TRT) for guiding the BOP to correctly align and interface with the tree. The BOP/running tool is lowered from a derrick that is mounted on a mobile offshore drilling unit (MODU), such as a drill ship or semi-submersible platform. The BOP/TRT is lowered on a segmented length of pipe called a workover riser string. The BOP/TRT is lowered by adding sections of pipe to the riser string until the BOP/TRT is sufficiently deep to allow landing on the tree. After the BOP is attached to the tree, the workover tool is lowered into the well through a lubricator mounted on the top of the riser string. The lubricator provides a sealing system at the entrance of the wireline that maintains the pressure and fluids inside the well and the riser string. The main disadvantage of this method is the large, specialized MODU that is required to deploy the riser string and the riser string needed to deploy the BOP.

FIG. 1A illustrates a prior art completed subsea well. A wellbore 10 has been drilled from a floor if of the sea 1 into a hydrocarbon-bearing (i.e., crude oil and/or natural gas) reservoir (not shown). A string of casing (not shown) has been run into the wellbore and set therein with cement (not shown). The casing has been perforated to provide to provide fluid communication between the reservoir and a bore of the casing. A wellhead (not shown) has been mounted on an end of the casing string. A string of production tubing 10 p (see FIG. 1B) may extend from the wellhead (not shown) to the formation to transport production fluid from the formation to the seafloor 1 f. A packer (not shown) may be set between the production tubing 10 p and the casing to isolate an annulus 10 a (see FIG. 1B) formed between the production tubing 10 p and the casing (not shown) from production fluid.

FIG. 1B illustrates a prior art horizontal production tree 50. The production tree 50 may be connected to the wellhead, such as by a collet, mandrel, or clamp tree connector. The tree 50 may be vertical or horizontal. If the tree is vertical (not shown), it may be installed after the production tubing 10 p is hung from the wellhead. If the tree 50 is horizontal (as shown), the tree may be installed and then the production tubing 10 p may be hung from the tree 50. The tree 50 may include fittings and valves to control production from the wellbore into a pipeline (not shown) which may lead to a production facility (not shown), such as a production vessel or platform. The tree 50 may also be in fluid communication with a hydraulic conduit (not shown) controlling a subsurface safety valve SSV 10 v (not shown).

The tree 50 may include a head 51, a wellhead connector 52, a tubing hanger 53, an internal cap 54, an external cap 55, an upper crown plug 56 u, a lower crown plug 56 l, a production valve 57 p, and one or more annulus valves 57 u,l. Each of the components 51-54 may have a longitudinal bore extending therethrough. The tubing hanger 53 and head 51 may each have a lateral production passage formed through walls thereof for the flow of production fluid. The tubing hanger 53 may be disposed in the head bore. The tubing hanger 53 may support the production tubing 10 p. The tubing hanger 53 may be fastened to the head by a latch 53 l. The latch 53 l may include one or more fasteners, such as dogs, and an actuator, such as a cam sleeve. The cam sleeve may be operable to push the dogs outward into a profile formed in an inner surface of the tree head 51. The latch 53 l may further include a collar for engagement with a running tool (not shown) for installing and removing the tubing hanger 53.

The tubing hanger 53 may be rotationally oriented and longitudinally aligned with the tree head 51. The tubing hanger 53 may further include seals 53 s disposed above and below the production passage and engaging the tree head inner surface. The tubing hanger 53 may also have a number of auxiliary ports/conduits (not shown) spaced circumferentially there-around. Each port/conduit may align with a corresponding port/conduit (not shown) in the tree head 51 for communicating hydraulic fluid or electricity for various purposes to tubing hanger 53, and from tubing hanger 53 downhole, such as for operation of the SSV. The tubing hanger 53 may have an annular, partially spherical exterior portion that lands within a partially spherical surface formed in tree head 51.

The annulus 10 a may communicate with an annulus passage formed through and along the head 51 for and bypassing the seals 53 s. The annulus passage may be accessed by removing internal tree cap 54. The tree cap 54 may be disposed in head bore above tubing hanger 53. The tree cap 54 may have a downward depending isolation sleeve received by an upper end of tubing hanger 53. Similar to the tubing hanger 53, the tree cap 54 may include a latch 54 l fastening the tree cap to the head 51. The tree cap 54 may further include a seal 54 s engaging the head inner surface. The production valve 57 p may be disposed in the production passage and the annulus valves 57 u,l may be disposed in the annulus passage. Ports/conduits (not shown) may extend through the tree head 51 to a tree controller (not shown) for electrical or hydraulic operation of the valves.

The upper crown plug 56 u may be disposed in tree cap bore and the lower crown plug 56 l may be disposed in the tubing hanger bore. Each crown plug 56 u,l may have a body with a metal seal on its lower end. The metal seal may be a depending lip that engages a tapered inner surface of the respective cap and hanger. The body may have a plurality of windows which allow fasteners, such as dogs, to extend and retract. The dogs may be pushed outward by an actuator, such as a central cam. The cam may have a profile on its upper end. The cam may move between a lower locked position and an upper position freeing dogs to retract. A retainer may secure to the upper end of body to retain the cam.

SUMMARY OF THE INVENTION

Embodiments of the present invention generally relate to retrieving a subsea tree plug. In one embodiment, a method for riserless intervention of a subsea well includes: lowering a pressure control assembly (PCA) from a vessel to a subsea production tree; fastening the PCA to the tree; deploying a plug running tool (PRT) into the PCA, wherein the PRT comprises a latch, an anchor, and a stroker; engaging the latch with a plug of the tree; engaging the anchor with the PCA; and operating the stroker to pull the latch and the plug from the tree.

In another embodiment, a plug running tool (PRT) for riserless intervention of a subsea well includes: a cablehead for connection to a wireline; a hydraulically operated anchor connected to the cablehead; a hydraulically operated stroker comprising a housing and a shaft, the housing connected to the anchor; an electric pump connected to the cablehead for operating the stroker and the anchor; and a latch connected to the shaft and comprising a gripper and an actuator operable to lock and release the gripper, wherein the PRT is tubular.

BRIEF DESCRIPTION OF THE DRAWINGS

So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments.

FIG. 1A illustrates a prior art completed subsea well. FIG. 1B illustrates a prior art horizontal production tree.

FIG. 2A illustrates a pressure control assembly (PCA), according to one embodiment of the present invention. FIG. 2B illustrates deployment of the PCA to the subsea production tree, according to another embodiment of the present invention. FIG. 2C illustrates deployment of a control pod to the PCA using an umbilical. FIG. 2D illustrates deployment and connection of a fluid conduit to the tree.

FIG. 3A illustrates a plug running tool (PRT) and a wireline module for deploying the PRT, according to another embodiment of the present invention. FIGS. 3B and 3C illustrate operation of a stroker of the PRT.

FIG. 4A illustrates deployment of the PRT and wireline module to the subsea production tree, according to another embodiment of the present invention. FIG. 4B illustrates connection of the wireline module to the PCA. FIG. 4C illustrates deployment of the PRT to the upper crown plug. FIG. 4D illustrates engagement of a latch of the PRT with the upper crown plug. FIG. 4E illustrates preparation of a stroker of the PRT to remove the upper crown plug. FIG. 4F illustrates removal of the upper crown plug. FIG. 4G illustrates washing the upper crown plug. FIG. 4H illustrates retrieval of the wireline module, PRT, and upper crown plug.

FIG. 5A illustrates deployment of a modified PRT to install a tree saver in the tree. FIG. 5B illustrates operation of the stroker to seat the tree saver in the tree. FIG. 5C illustrates release of the PRT from the tree saver. FIG. 5D illustrates the tree ready for intervention.

FIG. 6 illustrates an intervention operation being conducted using a coiled tubing module connected to the PCA, according to another embodiment of the present invention.

FIG. 7A illustrates a PRT having a vibratory jar, according to another embodiment of the present invention. FIGS. 7B-7D illustrate operation of the vibratory jar in upstroke mode.

DETAILED DESCRIPTION

FIG. 2A illustrates a pressure control assembly (PCA) 100, according to one embodiment of the present invention. The PCA 100 may include a tree adapter 105, a fluid sub 110, an isolation valve 115, a blow out preventer (BOP) stack 120, a tool housing (aka lubricator riser) 125, a frame 130, a manifold 135, a pod receptacle 140, and one or more accumulators 145 (two shown). The tree connector 105, fluid sub 110, isolation valve 115, BOP stack 120, and tool housing 125 may each include a housing or body having a longitudinal bore therethrough and be connected, such as by flanges, such that a continuous bore is maintained therethrough. The bore may have a large drift diameter, such as greater than or equal to four, five, six, or seven inches to accommodate a bottom hole assembly (BHA) of a workstring (discussed more below) and the crown plugs 56 u,l of the tree 50.

The tree adapter 105 may include a connector, such as dogs 105 d, for fastening the PCA 100 to an external profile 51 p of the tree 50 and a seal sleeve 105 s for engaging an internal profile 54 p of the tree. The tree adapter 105 may further include an electric or hydraulic actuator and an interface, such as a hot stab, so that a remotely operated subsea vehicle (ROV) 180 (see FIG. 2B) may operate the actuator for engaging the dogs 105 d with the external profile 51 p. The frame 130 may be connected to the tree connector 50, such as by fasteners (not shown). The manifold 135 may be fastened to the frame 130. The fluid sub 110 may include a housing having a bore therethrough and a port 110 p in communication with the bore. The port 110 p may be in fluid communication with the manifold 135 via a conduit (not shown).

The isolation valve 115 may include a housing, a valve member 115 v disposed in the housing bore and operable between an open position and a closed position, and an actuator 115 a operable to move the valve member between the positions. The actuator 115 a may be electric or hydraulic and may be in communication with a stab plate (not shown) of the pod receptacle 140. The isolation valve 115 may further operate as a check valve in the closed position: allowing fluid flow downward from the tool housing into the wellbore and preventing reverse fluid flow therethrough. Alternatively, the isolation valve 115 may be bi-directional when closed, the PCA 100 may further include a bypass conduit (not shown) connected to a port of a drain sub (not shown) disposed between the isolation valve and the BOP stack, and the drain port may include a check valve allowing downward flow and preventing reverse flow.

The BOP stack 120 may include one or more hydraulically operated ram preventers 120 b,w, such as a blind-shear preventer 120 b and one or more workstring preventers 120 w, such as a wireline preventer and a coiled tubing preventer (only one workstring preventer shown) connected together via bolted flanges. Each ram preventer 120 b,w may include two opposed rams disposed within a body. The body may have a bore that is aligned with the wellbore. Opposed cavities may intersect the bore and support the rams as they move radially into and out of the bore. A bonnet may be connected to the body on the outer end of each cavity and may support an actuator that provides the force required to move the rams into and out of the bore. Each actuator may include a hydraulic piston to radially move each ram and a mechanical lock to maintain the position of the ram in case of hydraulic pressure loss. The lock may include a threaded rod, a motor (not shown) for rotationally driving the rod, and a threaded sleeve. Once each ram is hydraulically extended into the bore, the motor may be operated to push the sleeve into engagement with the piston. Each actuator may include single (shown) or dual pistons (not shown). The blind-shear preventer 120 b may cut the workstring, such as coiled tubing, wireline, and even drill pipe, when actuated and seal the bore. The coiled tubing preventer may seal against an outer surface of coiled tubing when actuated and the wireline preventer may seal against an outer surface of the wireline when actuated.

The tool housing 125 may be of sufficient length to contain either a plug running tool (PRT) 300 (FIG. 3A) or a BHA (not shown) so that the PCA 100 may be closed while deploying either a wireline module 200 (FIG. 3A) or a coiled tubing module 400 (FIG. 6.) The tool housing 125 may have a connector profile 125 c for receiving an adapter of either workstring module 200, 400.

The pod receptacle 140 may be operable to receive a subsea control pod 160 (FIG. 2B). The receptacle may include a base 141, a latch 142, and an actuator 143. The base 141 be connected to the frame 130, such as by fasteners, and may include a landing plate for supporting the pod 160, a landing guide (not shown), such as a pin, and the stab plate. The stab plate may provide communication, such as electric (power and/or data), hydraulic, or optic, between the pod 160 and components of the PCA 100. The latch 142 may be pivoted to the base 141, such as by a fastener, and be movable by the actuator 143 between an engaged position (FIG. 2D) and a disengaged position (shown). The actuator 143 may be a piston and cylinder assembly connected to the frame 135 and the receptacle 140 may further include an interface (not shown), such as a hot stab, so that the ROV 180 may operate the actuator 143. The actuator 143 may also be in communication with the stab plate for operation by the pod 160. The latch 142 may include outer members and a crossbar (not shown) connected to each of the outer members by a shearable fastener 144. The actuator 143 may be dual function so that the latch may be locked in either of the positions by either the pod 160 or the ROV 180.

The control pod 160 may be in electric, hydraulic, and/or optic communication with a control van 151 onboard a support vessel 175 (FIG. 2B) via an umbilical 165 (FIG. 2D). The pod 160 may include one or more control valves (not shown) in communication with the BOP stack 120 (via the stab plate) for operating the BOP stack. Each control valve may include an electric or hydraulic actuator in communication with the umbilical 165. The umbilical 165 may include one or more hydraulic or electric control conduit/cables for each actuator. The accumulators 145 may store pressurized hydraulic fluid for operating the BOP stack 120. Additionally, the accumulators 145 may be used for operating one or more of the other components of the PCA 100. The accumulators 145 may be charged via a conduit of the umbilical 165 or by the ROV 180.

The umbilical 165 may further include hydraulic, electric, and/or optic control conduit/cables for operating valves of the manifold 135, the actuators 115 a, 143, tree valves 57 p,u,l and the various functions of the workstring modules 200, 400 (discussed below). The stab plate may further include an output for the workstring modules 200, 400 and an output for the tree 50. Each output may include an ROV operable connector for receiving a respective jumper 166, 266, 466 (aka flying lead) (FIGS. 2D, 4B, and 6). The ROV 180 may connect the tree jumper 166 to a control panel (not shown) of the tree 50 and the workstring jumpers 266, 466 to a respective control relay of the workstring modules 200, 400. The umbilical 165 may further include one or more layers of armor (not shown) made from a high strength metal or alloy, such as steel, for supporting the umbilical's own weight and weight of the control pod 160.

The control pod 160 may further include a microprocessor based controller, a modem, a transceiver, and a power supply. The power supply may receive an electric power signal from a power cable of the umbilical 165 and convert the power signal to usable voltage for powering the pod components as well as any of the PCA components. The PCA 100 may further include one or more pressure sensors (not shown) in communication with the PCA bore at various locations. The workstring modules 200, 400 may also include one or more pressure sensors in communication with a respective bore thereof at various locations. The pressure sensors may be in data communication with the pod controller. The modem and transceiver may be used to communicate with the control van 151 via the umbilical 165. The power cable may be used for data communication or the umbilical 165 may further include a separate data cable (electric or optic). The control van 151 may include a control panel (not shown) so that the various functions of the PCA 100, the tree 50, and the workstring modules 200, 400 may be operated by an operator on the vessel 175.

The control pod 160 may also include a dead-man's switch (not shown) for closing the BOP stack 120 in response to a loss of communication with the control van 151. Alternatively, instead of having individual conduits/cables for controlling each function of the PCA 100, tree 50, and workstring modules 200, 400, the pod controller may receive multiplexed instruction signals from the van operator via a single electric, hydraulic, or optic control conduit/cable of the umbilical 165 and then operate the various functions using individual conduits/cables extending from the control pod 160.

The manifold 135 may include one or more actuated valves (not shown) and one or more couplings, such as dry break coupling 147 f, for receiving a respective fluid conduit 170 (FIG. 2D) from the vessel 175. Actuators of the manifold valves and couplings of dry break connections 147 a (FIG. 2D, only one shown) may be in communication with the control pod 160 via the stab plate. Two fluid conduits 170 (only one shown) may extend from a vessel 175 to the manifold 135 for fluid circulation. A first one of the manifold valves may be in fluid communication with a first one of the couplings of dry break connections 147 a and a fluid conduit extending to the port 110 p. A second one of the manifold valves may be in fluid communication with a second one of the couplings (not shown) of dry break connections 147 a and another ROV operable connector for receiving a jumper 276, 476 (FIGS. 4B and 6) providing fluid communication with a respective junction plate of the workstring modules 200, 400.

The coupling 147 f may be a female coupling of a passive dry-break connection 147 p (FIG. 2D) (no actuator, tension release) and the dry break connections 147 a may each have actuators for release. Each of the dry break actuators may also have a shearable release. Suitable dry break connections are discussed and illustrated at FIGS. 3A-3C of U.S. patent application Ser. No. 13/095,596, filed Apr. 27, 2011 (Atty. Dock. No. WWCI/0010US), which is herein incorporated by reference in its entirety.

FIG. 2B illustrates deployment of the PCA 100 to the subsea production tree 50, according to another embodiment of the present invention. The support vessel 175 may be deployed to a location of the subsea tree 50. The support vessel 175 may be a light or medium intervention vessel and include a dynamic positioning system to maintain position of the vessel 175 on the waterline 1 w over the tree 50 and a heave compensator (not shown) to account for vessel heave due to wave action of the sea 1. Alternatively, the vessel 175 may be a MODU. The vessel 175 may further include a tower 178 located over a moonpool 177 and a winch 179. The winch 179 may include a drum having wire rope 190 wrapped therearound and a motor for winding and unwinding the wire rope, thereby raising and lowering a distal end of the wire rope relative to the tower. Alternatively, a crane (not shown) may be used instead of the winch and tower. The vessel 175 may further include a wireline winch 176.

The ROV 180 may be deployed into the sea 1 from the vessel 175. The ROV 180 may be an unmanned, self-propelled submarine that includes a video camera, an articulating arm, a thruster, and other instruments for performing a variety of tasks. The ROV 180 may further include a chassis made from a light metal or alloy, such as aluminum, and a float made from a buoyant material, such as syntactic foam, located at a top of the chassis. The ROV 180 may be controlled and supplied with power from vessel 175. The ROV 180 may be connected to support vessel 175 by an umbilical 181. The umbilical 181 may provide electrical (power), hydraulic, and/or data communication between the ROV 180 and the support vessel 175. An operator on the support vessel 175 may control the movement and operations of ROV 180. The umbilical 181 may be wound or unwound from drum 182.

The ROV 180 may be deployed to the tree 50. The ROV 180 may transmit video to the ROV operator for inspection of the tree 50. The ROV 180 may remove the external cap 55 from the tree 50 and carry the cap to the vessel 175. Alternatively, the winch 179 may be used to transport the external cap 55 to the waterline 1 w. The ROV 115 may then inspect an internal profile of the tree 50. The wire rope 190 may then be used to lower the PCA 100 to the tree 50 through the moonpool 177 of the vessel 175. The ROV 180 may guide landing of the PCA 100 on the tree 50. The ROV 180 may then operate the adapter connector 105 d to fasten the PCA 100 to the tree 50.

FIG. 2C illustrates deployment of the control pod 160 to the PCA 100 using the umbilical 165. The vessel 175 may further include a launch and recovery system (LARS) 150 for deployment of the control pod 160 and the umbilical 165. The LARS 150 may include a frame, an umbilical winch 152, a boom 153, a boom hoist 154, a load winch 155, and a hydraulic power unit (HPU, not shown). The LARS 150 may be the A-frame type (shown) or the crane type (not shown). For the A-frame type LARS 150, the boom 153 may be an A-frame pivoted to the frame and the boom hoist 154 may include a pair of piston and cylinder assemblies (PCAs), each PCA pivoted to each beam of the boom and a respective column of the frame. The HPU may include a hydraulic fluid reservoir, a hydraulic pump, and one or more control valves for selectively providing fluid communication between the reservoir, the pump, and the PCAs 154. The hydraulic pump may be driven by an electric motor.

The umbilical 165 may include an upper portion 161 and a lower portion 162 fastened together by a shearable connection 163. Each winch 152, 155 may include a drum having the respective umbilical upper portion 161 or load line 156 wrapped therearound and a motor for rotating the drum to wind and unwind the umbilical upper portion or load line 156. The load line 156 may be wire rope. Each winch motor may be electric or hydraulic. An umbilical sheave and a load sheave may each hang from the A-frame 153. The umbilical upper portion 161 may extend through the umbilical sheave and an end of the umbilical upper portion may be fastened to the shearable connection 163. The frame may have a platform for the control pod 160 to rest. The umbilical lower portion 162 may be coiled and have a first end fastened to the shearable connection 163 and a second end fastened to the control pod 160. The load line 161 may extend through the load sheave and have an end fastened to the lifting lugs of the control pod, such as via a sling. Pivoting of the A-frame boom 153 relative to the platform by the PCAs 154 may lift the control pod 160 from the platform, over a rail of the vessel 175, and to a position over the waterline 1 w. The load winch 155 may then be operated to lower the control pod 160 into the sea 1.

A length of the umbilical lower portion 162 may be sufficient to provide slack to account for vessel heave. A length of the umbilical lower portion 162 may also be sufficient so that the shearable connection 163 is at or slightly above a depth of a top of the workstring modules 200, 400. A length of the load line 156 may correspond to the length of the umbilical lower portion 162. As the load winch 155 lowers the control pod 160, the umbilical lower portion 162 may uncoil and be deployed into the sea 1 until the shearable connection 163 is reached. Once the shearable connection 163 is reached, a clump weight 164 may be fastened to a lower end of the umbilical upper portion 161. The control pod 160 may continue to be lowered using the load winch 155 until the shearable connection 163 and clump weight 164 are deployed from the LARS platform to over the waterline 1 w. The umbilical winch 161 may then be operated to support the control pod 160 using the umbilical 165 and the load line 156 slacked. The load line 156 and sling may be disconnected from the control pod 160 by the ROV 180. Alternatively, the load line 156 may be wireline and the sling may have an actuator in communication with the wireline so that the van operator may release the sling. The control pod 160 may then be lowered to a landing depth (clump weight 164 and shearable connection 163 at or above top of workstring module 200, 400) using the umbilical winch 152.

The PCA 100 may be deployed with the latch 142 locked in the disengaged position. Alternatively, the ROV 180 may operate the actuator 143 to disengage the latch after the PCA 100 has landed. As the control pod 160 is being lowered to the landing depth, the ROV 180 may grasp the control pod and assist in landing the control pod in the receptacle 140. Once landed, the ROV 180 may engage the latch 142 with the pod 160. The ROV 180 may then connect the jumper 166 to the tree control panel. The operator in the control van 151 may then close then close the tree valves 57 u,l,p and the SSV via the umbilical 165.

FIG. 2D illustrates deployment and connection of a fluid conduit 170 to the tree 50. An upper portion of each fluid conduit 170 may be coiled tubing 171. The vessel 175 may further include a coiled tubing unit (CTU, not shown) for each fluid conduit 170. Each CTU may include a drum having the coiled tubing 171 wrapped therearound, a gooseneck, and an injector head for driving the coiled tubing 171, controls, and an HPU. Alternatively, each CTU may be electrically powered. A lower portion of each fluid conduit 170 may include a hose 172. The hose 172 may be made from a flexible polymer material, such as a thermoplastic or elastomer or may be a metal or alloy bellows. The hose 172 may or may not be reinforced, such as by metal or alloy cords. An upper end of the hose 172 may be connected to the coiled tubing 171 by the passive dry beak connection 147 p and a lower end of the hose 172 may have a male coupling (of the actuated connection 147 a) connected thereto. The hose 172 may include two or more sections (only one section shown), each section fastened together, such as by a flanged or threaded connection. During deployment of the fluid conduit 170, a clump weight 173 may be fastened to the lower end of the coiled tubing 171.

The lower portion 172 of the fluid conduit 170 may be assembled on the vessel 175 and deployed into the sea 1 using the CTU. The coiled tubing 171 may be deployed until the clump weight 173 and passive dry break connection 147 p are at or slightly above a depth of a top of the workstring modules 200, 400. The ROV 180 may then grasp the male coupling of the actuated connection 147 a and guide the coupling to the manifold 135. A length of the hose 172 may be sufficient to provide slack in the fluid coupling 170 to account for vessel heave. The van operator may operate the dry break connection actuator to the unlocked position. The ROV 180 may then insert the male coupling into the female coupling and the van operator may lock the connection 147 a. The operation may then be repeated for the second fluid conduit.

An emergency disconnect system (EDS) may include the shearable fasteners 144, dry break connections 147 a,p, the shearable connection 163, the clump weights 164, 173, and the lower portions 162, 172. The EDS may allow the vessel 175 to drift or drive off in the event of a minor or major emergency (see FIGS. 5B and 5C of the '596 application and the accompanying discussion thereof).

FIG. 3A illustrates the PRT 300 and a wireline module 200 for deploying the PRT, according to another embodiment of the present invention. The wireline module 200 may include an adapter 205, a fluid sub 210, an isolation valve 215, one or more stuffing boxes 220 u,l, a grease injector 225, a frame 230, a control relay 260, an interface, such as a junction plate 235, a tool catcher 240, a grease reservoir 245 r, and a grease pump 245 p. The adapter 205, fluid sub 210, isolation valve 215, stuffing boxes 220 u,l, grease injector 225, and tool catcher 240 may each include a housing or body having a longitudinal bore therethrough and be connected, such as by flanges, such that a continuous bore is maintained therethrough.

The adapter 205 may include a connector for mating with the connector profile 125 c, thereby fastening the wireline module 200 to the PCA 100. The connector may be dogs or a collet. The adapter 205 may further include a seal face or sleeve and a seal (not shown). The adapter 205 may further include an actuator (not shown), such as a piston and a cam, for operating the connector. The adapter 205 may further include an ROV interface (not shown) so that the ROV 180 may connect to the connector, such as by a hot stab, and operate the connector actuator. Alternatively, the adapter 205 may have the connector profile instead of the connector and the tool housing 125 may have the connector in communication with the control pod 160 for operation by the van operator. The fluid sub 210 may include a housing having a bore therethrough and a port 210 p in communication with the bore. The port 210 p may be in fluid communication with the junction plate 235 via a conduit (not shown). The frame 230 may be fastened to the adapter 205 and the relay 260 and interface 235 may be fastened to the frame. The pump 245 p and reservoir 245 r may also be fastened to the frame 230.

The isolation valve 215 may include a housing, a valve member 215 v disposed in the housing bore and operable between an open position and a closed position, and an actuator 215 a operable to move the valve member between the positions. The actuator 215 a may be electric or hydraulic and may be in communication with the control relay 260 via a conduit (not shown). The actuator 215 a may fail to the closed position in the event of an emergency. The isolation valve 215 may be further operable to cut wireline 290 (FIG. 4A) when closed or the wireline module 200 may further include a separate wireline cutter. The isolation valve 215 may further operate as a check valve in the closed position: allowing fluid flow downward from the stuffing box 220 l toward the PCA 100 and preventing reverse fluid flow therethrough.

Each stuffing box 220 u,l may include a seal 220 s, a piston 220 a, and a spring 220 b disposed in the housing. A port 220 p may be formed through the housing in communication with the piston 220 a. The port 220 p may be connected to the control relay 260 via a hydraulic conduit (not shown). When operated by hydraulic fluid, the piston 220 a may longitudinally compress the seal 220 s, thereby radially expanding the seal inward into engagement with the wireline 290. The spring 220 b may bias the piston 220 a away from the seal 220 s and be set to balance hydrostatic pressure. Alternatively, an electric actuator may be used instead of the piston 220 a.

The grease injector 225 may include a housing integral with each stuffing box housing and one or more seal tubes 225 t. Each seal tube 225 t may have an inner diameter slightly larger than an outer diameter of the wireline 290, thereby serving as a controlled gap seal. An inlet port 225 i and an outlet port 225 o may be formed through the grease injector/stuffing box housing. A grease conduit (not shown) may connect an outlet of the grease pump 245 p with the inlet port 225 i and another grease conduit (not shown) may connect the outlet port 225 o with the grease reservoir 245 r. Another grease conduit (not shown) may connect an inlet of the pump 245 p to the reservoir 245 r. Alternatively, the outlet port 225 o may discharge into the sea 1. The grease pump 245 p may be electrically or hydraulically driven via cable/conduit (not shown) connected to the control relay 260 and may be operable to pump grease (not shown) from the grease reservoir 245 r into the inlet port 225 i and along the slight clearance formed between the seal tube 225 t and the wireline 290 to lubricate the wireline, reduce pressure load on the stuffing box seals 220 s, and increase service life of the stuffing box seals. The grease reservoir 245 r may be recharged by the ROV 180.

The tool catcher 240 may include a piston 240 a, a latch, such as a collet 240 c, a stop 240 s, a piston spring 240 b, and a latch spring 240 d disposed in a housing thereof. The collet 240 c may have an inner cam surface for engagement with a fishing neck of the PRT 300 and/or BHA and the catcher housing may have an inner cam surface for operation of the collet 240 c. The latch spring 240 d may bias the collet 240 c toward a latched position. The collet 240 c may be movable from the latched position to an unlatched position either by engagement with a cam surface of the fishing neck and relative longitudinal movement of the fishing neck upward toward the stop 240 s or by operation of the piston 240 a. Once the cam surface of the fishing neck/BHA has passed the cam surface of the collet 240 c, the latch spring 240 d may return the collet to the latched position where the collet may be engagable with a shoulder of the fishing neck, thereby preventing longitudinal downward movement of the PRT/BHA relative to the catcher 240. The catcher housing may have a hydraulic port 240 p formed through a wall thereof in fluid communication with the piston 240 a. A hydraulic conduit (not shown) may connect the hydraulic port to the control relay 260. The piston 240 a may be biased away from engagement with the collet 240 c by the piston spring 240 b. When operated, the piston 240 a may engage the collet 240 c and move the collet upward along the housing cam surface and into engagement with the stop 240 s, thereby moving the collet to the unlatched position. Alternatively, an electric actuator may be used instead of the piston.

The PRT 300 may be tubular and include a stroker 301, an electric pump 302, a cablehead 303, an anchor 310, and a latch 350. The stroker 301, electric pump 302, cablehead 303, and anchor 310, may each include a housing or body connected, such as by threaded connections. The stroker 301 may include the housing 305 and a shaft 309 (FIG. 3B). The cablehead 303 may include an electronics package (not shown) for controlling operation of the PRT 300. The electronics package may include a programmable logic controller (PLC) having a transceiver in communication with the wireline 290 for transmitting and receiving data signals to the vessel 175. The electronics package may also include a power supply in communication with the PLC and the wireline 290 for powering the electric pump, the PLC, and various control valves. The electric pump 302 may include an electric motor, a hydraulic pump, and a manifold. The manifold may be in fluid communication with the various PRT 300 components and include one or more control valves for controlling the fluid communication between the manifold and the components. Each control valve actuator may be in communication with the PLC. The cablehead 303 may connect the PRT 300 to the wireline module 200, such as by engagement of a shoulder with a corresponding shoulder formed in the stop 240 s. The anchor 310 may include two or more radial piston and cylinder assemblies and a die connected to each piston or two or more slips operated by a slip piston.

The latch 350 may include a housing 355. The housing 355 may be fastened to the shaft 309, such as by a threaded connection. The latch 350 may further include a gripper 360, such as a collet, connected to an end of the housing 355. The latch 350 may further include a locking piston 365 disposed in a chamber formed in the housing 355 and operable between a locked position in engagement with the collet 360 and an unlocked position disengaged from the collet. The locking piston 365 may be biased toward the locked position by a biasing member 375 l, such as a spring. The locking piston 365 may be in fluid communication with the stroker pump 302 via a passage 355 l formed through the housing 355, a passage (not shown) formed through the shaft 309 and via a hydraulic swivel (not shown) disposed between the stroker housing 305 and shaft.

The latch 350 may further include a release piston 370 disposed in a chamber formed in the housing 355 and operable between an extended position in engagement with a body of the crown plug 56 u and retracted position so as not to interfere with operation of the collet 360. The release piston 370 may be biased toward the retracted position by a biasing member 370 r, such as a spring. The release piston 370 may also be in fluid communication with the stroker pump 302 via a passage 355 r formed through the housing 355, a second passage (not shown) formed through the shaft 309 and via the hydraulic swivel (not shown) disposed between the stroker housing 305 and shaft. The release piston 370 may also serve as a landing shoulder. The release piston 370 may include a contact sensor or switch (not shown) in fluid or electrical communication with the PLC via a port or leads (not shown) extending through the housing 355 to the shaft 309 and from the shaft 309 to the stroker housing 305 via the swivel.

Alternatively, flexible conduit and/or flexible cable may be used instead of the hydraulic swivel.

FIGS. 3B and 3C illustrate operation of a stroker 301 of the PRT. The stroker 301 may include the housing 305 which is penetrated by the shaft 309. A piston 308 may be provided around the shaft 309 so that the shaft 309 may move longitudinally within the housing 305 for providing the longitudinal force P. The piston 308 may be provided with a seal 316 in order to provide a sealing connection between the inside of the housing 305 and the outside of the piston 308.

The housing 305 may include a tube 314 which is closed by two rings 315 for forming a chamber 325. The rings 315 may each have a seal 316, such as an O-ring, in order to provide a sealing connection between the rings 315 and the shaft 309. In this way, the chamber 325 may be divided into upper 325 u and lower 325 l portions. Each portion may be in fluid communication with the pump 302 via respective ducts 313. The pump 302 may pump hydraulic fluid 311 into the upper portion 325 u by sucking a corresponding amount of hydraulic fluid 311 from the lower portion 325 l. Thus, the piston 308 and, consequently, the shaft 309 are driven forward and away from the pump 302 providing the longitudinal force P downward. Operation of the stroker may be reversed by reversing operation of the pump 302 or by including directional valves in the manifold.

The upper portion 325 u may be provided with a duct 313 at the end closest to the pump 302, and the lower portion 325 l may be provided with a duct 313 at the rearmost end in relation to the pump 302. In this way, the fluid 311 can be sucked or pumped into each chamber until the piston 308 almost abuts the ring 315 of the housing 305. The PRT 300 may be a closed system, meaning that the same fluid is recirculated being pumped back and forth to operate the various components.

Additionally, the stroker 301 may have two or more chambers in order to provide more longitudinal force P. Each chamber may be independently operated by the PLC in order to control the longitudinal force exerted by the stroker. For example, the tube 314 may be divided by five rings 315 into four chambers 325 (not shown). The shaft 309 may penetrate all of the chambers 325 and four pistons 308 may be provided on the shaft 309 so that each piston 308 is provided in one of the four piston chambers 325. The additional ducts 313 connecting the pump 302 to the chambers 325 may be placed along the circumference of the tube 314.

Six sets of ducts 313 can be seen in the cross-sectional view of FIG. 3C. The twelve ducts 313 may be used to lead fluid 311 back and forth between six chambers 325 or each chamber portion may have multiple ducts leading thereto. For example, four sets of ducts 313 may provide fluid 311 for four chambers 325, and the last two sets of ducts 313 may be extra fluid connections to the two chambers 225 positioned furthest from the pump 302 so as to compensate for the extra distance the fluid 311 has to travel.

Alternatively, the PRT 300 may be deployed and operated with coiled tubing 490 or electric coiled tubing instead of wireline 290 and the pump may be omitted and a pump of the vessel 100 used instead. Alternatively, the PRT 300 may be electrically operated instead of hydraulically operated.

As shown in FIG. 3C, the housing 305 may include an outer tube 314 o and an inner tube 314 i. The outer tube 314 o may be constructed to withstand the pressure difference between the tube bore and its surroundings. A wall 320 i of the inner tube 314 i may be substantially thinner than a wall 320 o of the outer tube 314 o. The outside of the inner tube 314 i may be provided with grooves 319 that define the ducts 313 when the inner tube 314 i is positioned in the outer tube 314 o.

FIG. 4A illustrates deployment of the PRT 300 and wireline module 200 to the subsea production tree 50, according to another embodiment of the present invention. FIG. 4B illustrates connection of the wireline module 200 to the PCA 100. To prepare for intervention (or abandonment), the wireline 290 may be fed through the tower 178 and inserted through the wireline module 200 and connected to the PRT 300. The PRT 300 may then be connected to the tool catcher 240. The wireline module 200 may then be deployed through the moonpool 177 using the wireline winch 176 and landed on the tool housing 125. The ROV 180 may operate the adapter connector, thereby fastening the wireline module 200 to the PCA 100. The ROV 180 may then connect jumper 266 to the control pod 160 and control relay 260 and connect fluid conduit 276 to the manifold 135 and the junction box 235. The van operator may then engage one or both of the stuffing boxes with the wireline 290. The van operator may then release the PRT 300 from the tool catcher 240 via the umbilical 165 and control relay 260.

FIG. 4C illustrates deployment of the PRT 300 to the upper crown plug 56 u. The van operator may supply electrical power to the PLC via the wireline 290. The van operator may then feed wireline 290 from the winch 176 toward the tree 50, thereby lowering the PRT 300 to the upper crown plug 56 u. The van operator may also instruct the PLC to retract the locking piston 365 and the PLC may respond by supplying hydraulic fluid to the passage 355 l, thereby retracting the locking piston to the unlocked position. The PRT 300 may be lowered until the collet 360 engages the cam of the upper crown plug 56 u. The engagement depth may be recorded by the PLC and/or control panel for later reference. Interaction of corresponding profiles may force the collet fingers 360 radially inward until the collet fingers are in alignment with the cam profile at which point stiffness of the collet fingers may snap the fingers into engagement with the profile.

FIG. 4D illustrates the latch 350 engaged with the upper crown plug 56 u. Simultaneously or shortly thereafter, the release piston 370 may contact the crown plug body, thereby activating the contact switch/sensor. The locking piston 365 may then be moved to the locked position by relief of hydraulic pressure, thereby allowing the spring 370 l to extend the locking piston 365 to the locked position and preventing disengagement of the collet 360 from the upper crown plug 56 u.

FIG. 4E illustrates preparation of the stroker 301 to remove the upper crown plug 56 u. The van operator may then instruct extension of the stroker shaft 309. The PLC may supply hydraulic fluid to the stroker piston 308 to extend the shaft 309. Once the shaft 309 is extended, the van operator may instruct the PLC to set the anchor 310 and the PLC may supply hydraulic fluid to the anchor, thereby extending the anchor into engagement with the adapter 105. Alternatively, the PRT 300 may be configured so that the anchor engages the tool housing 125.

FIG. 4F illustrates removal of the upper crown plug 56 u. The van operator may then instruct retraction of the stroker shaft 309. The PLC may supply hydraulic fluid to the stroker piston 308 to retract the shaft 309. The stroker may exert force P necessary to disengage the upper crown plug 56 u from the internal cap 54. The stroker force P may be substantially greater than a force capacity of the wireline 290, such as greater than or equal to ten, twenty, or thirty thousand pounds. As the shaft 309 retracts, the crown plug cam may be moved upward relative to the body until the cam engages a shoulder of the body, thereby creating a cavity for the dogs to retract. The cam may then pull on the body which may push the dogs into engagement with a profile of the internal tree cap 54, thereby forcing the dogs radially inward into the cavity. The crown plug 56 u may then be free from the cap 54.

Additionally, the van operator may add slack to the wireline 290 before operation of the stroker 301 to remove the plug 56 u so that the vessel 100 may be moved away from the tree 50 by a safe distance should a blowout occur in response to removing the plug.

FIG. 4G illustrates washing the upper crown plug 56 u. The PRT 300 and upper crown plug 56 u may then be raised until the cablehead 303 reengages the tool catcher 240. The van operator may then close the isolation valve 115. The PRT 300 and upper crown plug 56 u may then be washed by injecting a hydrates inhibitor 390 from the vessel 175, through the fluid conduit 170, the manifold, the conduit 266, the junction plate 235, and into the wireline module port 210 p. The spent inhibitor may be returned to the vessel 175 through the port 110 p, the manifold 135, and the second fluid conduit (as discussed above, isolation valve 115 may allow downward flow when closed or the PCA 100 may include a bypass).

Additionally, the PRT 200 may include a flushing system (not shown) to remove debris from the crown plugs to prevent the debris from obstructing removal of the crown plugs. The respective crown plug may be flushed before engaging the latch therewith. The flushing system may include a nozzle connected to the housing 355 and in communication with the stroker pump 302. The stroker 301 may include a cleaning fluid reservoir and discharge cleaning fluid through the nozzle, thereby impinging a fluid jet onto the crown plug 56 u.

FIG. 4H illustrates retrieval of the wireline module 200, PRT 300, and upper crown plug 56 u. Once washing is complete, the blind-shear preventer 120 b may also be closed. The adapter connector may then be released by the ROV 180 and the wireline module 200 and upper crown plug 56 u may be retrieved to the vessel 175. The operation may then be repeated for the lower crown plug 56 l.

FIG. 5A illustrates deployment of a modified PRT 300 t to install a tree saver 395 in the tree 50. The wireline module 200 and PRT 300 t may then be deployed again with a tree saver 395. The tree saver 395 may include a sleeve with a metal seal on its outer surface. The metal seal may be a depending lip that engages a tapered inner surface of the internal tree cap 54. Alternatively, the tree saver metal seal may engage the tubing hanger 53 instead of the tree cap 54. The sleeve may have a plurality of windows which allow fasteners, such as dogs, to extend and retract. The dogs may be pushed outward by an actuator, such as a central cam. The cam may have a profile on its upper end. The cam may move between a lower locked position and an upper position freeing dogs to retract. A retainer may secure to the upper end of body to retain the cam. The tree saver 395 may further include one or more seals. The seals may each be made from a polymer, such as an elastomer. The sleeve may have a length sufficient to extend past the production passage and the lower seal may engage an inner surface of the tubing hanger 53, thereby isolating the production passage from any harmful fluids used during the intervention operation, such as cement or fracing fluid. Alternatively, the sleeve may extend into the production tubing 10 p and the lower seal may engage an inner surface of the production tubing. The sleeve may also extend upward to the tree adapter 105 and the upper seal may engage an inner surface of the adapter sleeve 105 s. Alternatively, the sleeve portion extending from the dogs to the tree connector and the upper seal may be omitted.

FIG. 5B illustrates operation of the stroker 301 t to seat the tree saver 395 in the tree 50. FIG. 5C illustrates release of the PRT 300 t from the tree saver 395. FIG. 5D illustrates the tree 50 ready for intervention. The PRT 300 t may be released from the tool catcher 240 and lowered until the tree saver dogs are proximate to the upper crown plug profile in the internal cap 54. The anchor 310 may then be extended into engagement with the tool housing 125. The stroker 301 t may then be extended to engage the tree saver lip with a shoulder of the internal tree cap 54. The collet 360 t may push the tree saver dogs into the internal cap profile. Once the shaft 309 t has extended, the release piston 370 may be extended until contact with the tree saver body and the locking piston 365 t may be moved to the unlocked position. The shaft 309 t may then be retracted while pressure is maintained on the release piston 370. The release piston 370 may continue to extend while the shaft 309 t retracts, thereby holding the tree saver 395 downward against the cap profile and allowing the collets 360 t to release from the locking sleeve. Retraction of the shaft 309 may be choked to ensure that the release piston 370 maintains contact with the tree saver body. The PRT 300 t may then be raised until the cablehead 303 reengages the tool catcher 240. The PRT 300 t may be washed, as discussed above for the upper crown plug. The PRT 300 t and the wireline module 200 may then be retrieved to the vessel. The tree 50 may now be ready for an intervention operation.

Alternatively, the anchor 310 may engage the adapter 105. Alternatively, the retrieval piston 370 may be extended and used for a position sensor to determine when to operate the anchor 310. Alternatively, the deployment depth may be determined using the removal depth of the upper crown plug 56 u.

FIG. 6 illustrates an intervention operation being conducted using a coiled tubing module 400 connected to the PCA 100, according to another embodiment of the present invention. For a more detailed view of the coiled tubing module 400, see FIG. 2C of U.S. patent application Ser. No. 13/018,871, filed Feb. 1, 2011 (Atty. Dock. No. WWCI/0011US), which is herein incorporated by reference in its entirety. Alternatively, the wireline module 200 may be used to conduct the intervention or abandonment operation. The coiled tubing module 400 may include an adapter, a fluid sub, an isolation valve, a stripper, a subsea coiled tubing injector, a frame, a control relay, an interface, such as a junction plate, and a tool catcher. The adapter, fluid sub, isolation valve, stripper, and tool catcher may each include a housing or body having a longitudinal bore therethrough and be connected, such as by flanges, such that a continuous bore is maintained therethrough. The adapter may be similar to the wireline adapter. The frame may be fastened to the adapter and the relay and the interface may be fastened to the frame. The fluid sub may include a housing having a bore therethrough and a port in communication with the bore. The port may be in fluid communication with the junction plate via a conduit (not shown). The tool catcher may be similar to the wireline tool catcher.

The isolation valve may include a housing, a valve member disposed in the housing bore and operable between an open position and a closed position, and an actuator operable to move the valve member between the positions. The actuator may be electric or hydraulic and may be in communication with the control relay via a conduit (not shown). The actuator may fail to the closed position in the event of an emergency. The isolation valve may be further operable to cut coiled tubing 490 when closed or the coiled tubing module 400 may further include a separate coiled tubing cutter. The isolation valve may further operate as a check valve in the closed position: allowing fluid flow downward from the stripper toward the PCA 100 and preventing reverse fluid flow therethrough.

The stripper may include a seal and a piston disposed in the housing. A hydraulic packoff port and a hydraulic release port may be formed through the housing in fluid communication with a respective face of the piston. Each port may be connected to the control relay via a respective hydraulic conduit. When operated by pressurized hydraulic fluid via the pack-off port, the piston may longitudinally compress the seal, thereby radially expanding the seal inward into engagement with the coiled tubing. The seal may be released by application of pressurized hydraulic fluid via the release port. Alternatively, an electric actuator may be used instead of the piston. Alternatively, the stripper may include a spring instead of the release port.

The injector may include a traction assembly to engage the coiled tubing 490 and drive the coiled tubing into or out of the wellbore 10. The traction assembly may include opposing chain loops guided by bearing assemblies. Gripping members may be secured to individual links of the chain loops, so as to grip the coiled tubing. The gripping members and the chain loops may thus move together longitudinally at the area of contact with the coiled tubing 490 to move the coiled tubing into or out of the wellbore 10. A plurality of rollers may be secured to the links of the chain loops, and roll along support members. The support members may be moved laterally inwardly to urge the gripping members into engagement with the coiled tubing 490 with sufficient force to grip the coiled tubing. The rollers may allow for a large lateral load to be applied without inducing a significant longitudinal drag load.

The bearing assemblies and an injector gear case may both be sealed to retain lubricant and prevent intrusion of seawater. The bearing assemblies may be outboard bearing assemblies because the portion of the housing adjacent the sealed gear case may be open to seawater to accommodate the chain loops. The chain loops may be routed over sprockets or gears within the housing, rotating about the axis of the bearings assemblies, and the chain loops may thus be guided by the bearing assemblies. A hydraulic or electric drive motor may drive the chain loops. The drive motor may be in hydraulic/electric communication with the control relay via a conduit/cable. The gear case may house a plurality of gears which may be driven by the drive motor and which may drive the chain loops via a drive shaft sealably extending from the sealed gear case.

The injector may further include a lubricant reservoir. The reservoir may compensate pressure within the gear case, each outboard bearing assembly, and other components of the injector that are sealed and sensitive to pressure differentials, such as the rollers. The reservoir may include a housing structurally separate from and attached to an outer housing of the gear case. The reservoir housing may be divided into a compensator chamber and a lubricant chamber by a pressure compensator, such as a piston or diaphragm. The lubricant chamber maybe filled with a lubricant. A conduit may be used to fluidly connect and pass lubricant between the reservoir and the gear case, the bearing assemblies, the rollers, and other sealed components. The compensator chamber may be in fluid communication with the sea by a port formed through the reservoir housing. As the hydrostatic pressure surrounding the reservoir increases, such as when the injector is lowered into a subsea environment, the compensator may pressurize the lubricant, thereby equalizing or substantially equalizing the lubricant pressure and the hydrostatic seafloor pressure. The compensator may be biased so that the lubricant pressure is slightly greater than the seafloor pressure. Accordingly, the pressure differential that would otherwise exist between the seawater environment and the interior of the sealed components is reduced or eliminated.

The vessel 400 may further include an additional CTU (second or third) including an injector head 425, drum 420, gooseneck, and HPU (not shown). The coiled tubing 490 may be inserted through the coiled tubing module 400 and connected to the BHA (not shown). The BHA may include one or more tools operable to perform an intervention or abandonment operation in the wellbore 10. The BHA may then be connected to the tool catcher. The injector head 425 may be deployed over the moonpool 177 and the coiled tubing module 400 may be lowered to the tree 50 using the vessel injector 425 and the coiled tubing 490.

Once the coiled tubing adapter has landed onto the PCA 100, the ROV 180 may operate the adapter connector, thereby fastening the coiled tubing module 400 to the PCA 100. The ROV 180 may then connect a jumper 466 to the control pod 160 and control relay and connect fluid conduit 476 to the manifold 135 and the junction box. Once fastened, the vessel injector 425 may feed the coiled tubing 490 toward the tree 50, thereby creating slack in the coiled tubing 490. The vessel 175 may then (or simultaneously) be moved a distance from the tree 50 ensuring safety of the vessel 400 should a blowout occur during the intervention operation. The slack may also serve to compensate for heave of the vessel.

The stripper may be engaged with the coiled tubing 490 by the van operator and then the isolation valve 115, blind-shear BOP 120 b, and SSV may be opened. The van operator may then release the BHA from the tool catcher via the umbilical 350 and control relay. The subsea drive motor may then be operated by the van operator, thereby advancing the BHA toward the tree 50. The slack may be maintained through synchronization of the vessel injector 425 with the subsea injector by communication with the surface controller. The coiled tubing 490 may continue be advanced (while maintaining the slack via synchronous operation of the vessel injector 425) into the wellbore 10 by the subsea injector until the BHA reaches a desired depth in the wellbore. The intervention or abandonment operation may then be conducted using the coiled tubing 490 and the BHA. To facilitate the intervention or abandonment operation, fluid may be pumped through the coiled tubing 490 and the BHA and returned to the vessel 175 via the port 110 p. Further, fluid may be pumped into the wellbore 10 before or after deployment of the BHA through the port 110 p with the isolation valve 115 closed, thereby protecting the BOP stack 120 from the fluid.

Once the intervention or abandonment operation has concluded, the BHA and coiled tubing 490 may be retrieved from the wellbore 10 by reversing the deployment and landing procedure, discussed above. The isolation valve 115 and SSV may then be closed by the vessel operator. The BHA may then be washed as discussed above for the upper crown plug 56 u. The blind-shear preventer 120 b may then be closed. The vessel 175 may return to the position over the tree 50. The slack may be removed from the coiled tubing 490 by the vessel injector (after or simultaneously with vessel movement). The ROV 180 may disconnect the adapter connector and the coiled tubing module 400 may be retrieved from the tree 50. If an intervention operation was conducted, the tree saver 395 may be removed and the crown plugs 56 u,l reinstalled using the wireline module 200 and PRT 300/300 t. Reinstallation of the crown plugs 56 u,l may be similar to installation of the tree saver 395, discussed above, and removal of the tree saver may be similar to removal of the crown plugs. Additionally, a vent (not shown) in communication with a portion of the bore between the crown plugs 56 u,l may be opened to prevent fluid lock between the crown plugs. The PCA 100 may then be retrieved and the well returned to production.

FIG. 7A illustrates a PRT 500 having a vibratory jar 501, according to another embodiment of the present invention. The PRT 500 may include the cablehead 303, one or more electric pumps 302, 502 the stroker 301/301 t, a vibratory jar 501, the anchor 310, the latch 350/350 t, a control head 503, and a reservoir 575. The vibratory jar 501 may include a housing 505 and a knocker 509. The cable head 303 may control operation of the stroker 301/301 t and the anchor 310 and the control head 503 may include an electronics package (not shown) for controlling operation of the vibratory jar 501 and the latch 350/350 t. The control head 503 may be in electrical communication with the wireline 290 via a flexible cable 580. The electronics package may include a programmable logic controller (PLC) having a transceiver in communication with the wireline 290 for transmitting and receiving data signals to the vessel 100. The electronics package may also include a power supply in communication with the PLC and the wireline 290 for powering the electric pump 502, the PLC, and various control valves. The electric pump 502 may include an electric motor, a hydraulic pump, and a manifold. The manifold may be in fluid communication with the jar housing 505 via an internal bore, latch 350/350 t, via flexible conduit 582, and the reservoir 575, via flexible conduit 581, and include one or more control valves for controlling the fluid communication between the manifold and the components. Each control valve actuator may be in communication with the PLC.

The cable and control head PLCs may each be connected to the wireline 290 in a parallel arrangement and each of the cable head PLC and the control head PLC may have a unique address so that the vessel 175 may send selectively send commands to each one. Alternatively, the control head PLC may instead be connected to the cable head PLC (series arrangement) and the control head PLC may relay instructions to the control head PLC and the cable head power supply may provide electricity to the control head power supply. Alternatively, the control head 503 and pump 502 may be omitted and the jar 501 and latch 350/350 t may be operated by a flexible conduits or hydraulic swivels in communication with the stroker pump manifold.

FIGS. 7B-7D illustrate operation of the vibratory jar 501 in upstroke mode. The housing 505 may be connected to the pump 502, such as with threaded connection 517 and the knocker 509 may be connected to the reservoir 575, such as with threaded connection 547. The jar 501 may be operated after the latch has engaged one of the crown plugs 56 u,l and/or the tree saver 395 and as the stroker shaft 309/309 t is retracted to facilitate removal thereof especially if the crown plug/tree saver is stuck due to obstruction by debris and/or corrosion. Retraction of the stroker shaft 309/309 t may cause the jar 501 to be in tension with knocker 509 in an extended position with respect to housing 505 with the tension force being transmitted to knocker 509 via pins 535.

Referring specifically to FIG. 7B, to operate the jar 501, hydraulic fluid may be injected into housing conduit 521 using the pump 502. Fluid pressure within the upper portion of housing 505 may act on dart 550 and piston 561 of mandrel 557 to urge dart 550 and mandrel 557 longitudinally downward to space apart upwardly facing shoulder 526 of hammer 525 from downwardly facing shoulder 553 of knocker 509, thereby closing valve 560. When valve 560 is closed, the pressure within flow passage 559 of mandrel 557 may be less than the pressure within the upper portion of housing 505. Thus, dart 550 may be urged continually into sealing contact with mandrel 557 and may move therewith as a unit. The downward movement of dart 550 and mandrel 557 may compress both dart spring 507 and main spring 513.

Referring specifically to FIG. 7C, the downward movement of dart 550 and mandrel 557 may continue until shoulder 551 of dart 550 contacts shoulder 515 of housing 505, thereby halting downward movement of dart 550. Fluid pressure applied to the upper surface of piston 561 may continue to urge mandrel 557 downwardly, thereby breaking the seal between ball closure member 563 and seat 565. When the seal between ball 563 and seat 565 is broken, the differential pressure across dart 550 may be effectively removed and dart 550 may be free to be moved longitudinally upward by dart spring 507. Additionally, mandrel 557 may be free to be moved longitudinally upward by main spring 513.

Referring specifically to FIG. 7D, the dart 550 may be moved longitudinally upward until valve member 517 engages seat 519 of conduit 521, thereby momentarily interrupting the flow of fluid through the jar 501. Mandrel 557 may also be moved sharply upward by main spring 513 such that hammer 525 forcefully impacts (aka jars) 570 internal anvil 553 of knocker 509, thereby also jarring the connected latch 350/350 t and crown plug/tree saver. Should the blow 570 move the crown plug/tree saver and latch upwardly, knocker 509 may be free to move upwardly with respect to housing 505 by the sliding action of pins 535 within slots 537.

After the impact 570 of hammer 525 upon internal anvil 553 of knocker 509, the jar 501 may return to the position depicted in FIG. 7B and repeat the operating cycle. At typical pressures and flow rates, the jar 501 may operate at one or more cycles per second, thereby creating an upward jarring vibration. The upwardly jarring vibration may continue as long as the jar 501 is in tension and fluid flow is maintained. Fluid flow through passage 559 may continue into reservoir 575 where the fluid may be recycled. A frequency of the jar 501 may be varied by varying a speed of the pump 502. The PRT 500 may further include a contact switch or sensor for detecting when the crown plug/tree saver has been freed in communication with the control head PLC. The PLC may halt circulation to the jar 501 in response to detecting freedom of the crown plug/tree saver.

Additionally, the jar 501 may be operated in a downstroke mode (not shown) to facilitate reinstallation of the crown plugs/tree saver. The jar 501 may be operated as the stroker shaft is being extended to reinstall a respective crown plug/tree saver. Discussion and illustration of the downstroke mode may be found in U.S. Pat. No. 4,462,471, which is herein incorporated by reference in its entirety.

While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow. 

1 A method for riserless intervention of a subsea well, comprising: lowering a pressure control assembly (PCA) from a vessel to a subsea production tree; fastening the PCA to the tree; deploying a plug running tool (PRT) into the PCA, wherein the PRT comprises a latch, an anchor, and a stroker; engaging the latch with a plug of the tree; engaging the anchor with the PCA; and operating the stroker to pull the latch and the plug from the tree.
 2. The method of claim 1, wherein: the PRT further comprises a jar, and the method further comprises operating the jar as the stroker pulls the latch and the plug, thereby jarring the latch and the plug.
 3. The method of claim 2, wherein: the jar is a vibratory jar, and the latch and the plug are repeatedly jarred at a frequency greater than or equal to one cycle per second.
 4. The method of claim 1, further comprising: retrieving the PRT and plug to the vessel; deploying a second PRT carrying a tree saver into the PCA; and connecting the tree saver to the tree using the second PRT.
 5. The method of claim 1, wherein: the PRT is deployed from the vessel using a workstring, the PRT carries a workstring module during deployment, and the PRT is deployed by: fastening the workstring module to the PCA; and engaging a seal of the workstring module with the workstring.
 6. The method of claim 5, further comprising: washing the plug and PRT within the workstring module and PCA with a hydrates inhibitor; releasing the workstring module from the PCA; and retrieving the workstring module, the washed PRT, and the washed plug to the vessel.
 7. The method of claim 5, further comprising, before operation of the PRT: slacking the workstring; and moving the vessel a safe distance from the tree.
 8. The method of claim 5, further comprising: releasing the workstring module from the PCA; retrieving the workstring module, the PRT, and the plug to the vessel; deploying an intervention bottomhole assembly (BHA) from the vessel using a second workstring, the BHA carrying a second workstring module; fastening the second workstring module to the PCA; engaging a seal of the second workstring module with the second workstring; and deploying the BHA into the wellbore.
 9. A plug running tool (PRT) for riserless intervention of a subsea well, comprising: a cablehead for connection to a wireline; a hydraulically operated anchor connected to the cablehead; a hydraulically operated stroker comprising a housing and a shaft, the housing connected to the anchor; an electric pump connected to the cablehead for operating the stroker and the anchor; and a latch connected to the shaft and comprising a gripper and an actuator operable to lock and release the gripper, wherein the PRT is tubular.
 10. The PRT of claim 9, further comprising a jar comprising a housing connected to the shaft and a knocker connected to the latch.
 11. The PRT of claim 10, wherein: the jar further comprises a valve and a hammer, and the valve is operable to reciprocate the hammer in response to hydraulic fluid pumped through the jar.
 12. A system for riserless intervention of a subsea well, comprising: the PRT of claim 9; and a wireline module, comprising: a bore formed therethrough; an adapter having a connector for fastening the wireline module to a pressure control assembly (PCA) and a seal face for engaging the PCA; a tool catcher connected to the adapter and operable to receive the cablehead; a frame connected to the adapter; a stuffing box connected to the tool catcher and comprising a seal and an actuator operable to engage and disengage the seal with/from the wireline; and a grease injector connected to the stuffing box and operable to lubricate the wireline; a grease pump connected to the frame and in fluid communication with the grease injector; a grease reservoir connected to the frame and in fluid communication with the grease pump.
 13. The system of claim 12, wherein the wireline module further comprises: a fluid sub connected to the tool catcher and having a port in communication with the bore; and an isolation valve connected to the fluid sub and operable to close the bore.
 14. The system of claim 12, wherein the wireline module further comprises: a control relay connected to the frame and operable to interface with a control pod of the PCA; and a manifold connected to the frame and operable to interface with a manifold of the PCA.
 15. The system of claim 12, further comprising: the PCA, comprising: a bore formed therethrough; a production tree adapter having a connector for fastening the PCA to a subsea production tree and a seal sleeve for engaging an internal profile of the tree; a frame connected to the adapter; a fluid sub connected to the adapter and having a port in communication with the bore; an isolation valve connected to the fluid sub and operable to close the bore; a blow out preventer (BOP) connected to the isolation valve and operable to shear the wireline and close the bore; an accumulator for storing pressurized hydraulic fluid to operate the BOP; a tool housing connected to the BOP; a control pod receptacle connected to the frame for receiving a control pod; and a manifold connected to the frame for receiving a fluid conduit from a vessel. 